The present invention relates to earth-penetrating drill bits, and particularly to rotary-cone rotating bits such as are used for drilling oil and gas wells.
Background: Rotary Drilling
Oil wells and gas wells are drilled by a process of rotary drilling. In a conventional drill rig, as seen in FIG. 5 a drill bit 50 is mounted on the end of a drill string 52, made of many sections of drill pipe, which may be several miles long. At the surface a rotary drive turns the string, including the bit at the bottom of the hole, while drilling fluid (or “mud”) is pumped through the string by very powerful pumps 54.
The bit's teeth must crush or cut rock, with the necessary forces supplied by the “weight on bit” (WOB) which presses the bit down into the rock, and by the torque applied at the rotary drive. While the WOB may in some cases be 100,000 pounds or more, the forces actually seen at the drill bit are not constant: the rock being cut may have harder and softer portions (and may break unevenly), and the drill string itself can oscillate in many different modes. Thus the drill bit must be able to operate for long periods under high stresses in a remote environment.
When the bit wears out or breaks during drilling, it must be brought up out of the hole. This requires a process called “tripping”: a heavy hoist pulls the entire drill string out of the hole, in stages of (for example) about ninety feet at a time. After each stage of lifting, one “stand” of pipe is unscrewed and laid aside for reassembly (while the weight of the drill string is temporarily supported by another mechanism). Since the total weight of the drill string may be hundreds of tons, and the length of the drill string may be tens of thousands of feet, this is not a trivial job. One trip can require tens of hours and is a significant expense in the drilling budget. To resume drilling the entire process must be reversed. Thus the bit's durability is very important, to minimize round trips for bit replacement during drilling.
Background: Drill Bits
One of the most important types of rotary drill bits commonly used in drilling for oil and gas is the roller cone bit, seen in FIG. 6. In such bits, a rotating cone 82 with teeth 84 on its outer surface is mounted on an arm 46 of the drill bit body. The arms 46 (typically three) extend downhole from the bit body, and each carries a spindle on which the cone is mounted with heavy-duty bearings. The support arms are roughly parallel to the drill string, but the spindles are angled to point radially inward and downhole.
As the drill bit rotates, the roller cones roll on the bottom of the hole. The weight-on-bit forces the downward pointing teeth of the rotating cones into the formation being drilled, applying a compressive stress which exceeds the yield stress of the formation, and thus inducing fractures. The resulting fragments are flushed away from the cutting face by a high flow of drilling fluid.
The drill string typically rotates at 150 rpm or so, and sometimes as high as 1000 rpm if a downhole motor is used, while the roller cones themselves typically rotate at a slightly higher rate. At this speed the roller cone bearings must each carry a very bumpy load which averages a few tens of thousands of pounds, with the instantaneous peak forces on the bearings several times larger than the average forces. This is a demanding task.
Background: Selection of Insert Shapes
A wide variety of shapes have been used for the inserts of roller-cone-type bits. These include, for example, hemispherical inserts, where the exposed surface is generally spherical; pointed inserts, which are also axisymmetric but rise higher, for a given insert diameter, than hemispherical inserts would; chisel-shaped inserts, having a “crest” orientation; and more complex shapes. Insert design and selection is itself a complex and highly developed area of engineering.
Proper insert selection depends on the formation being drilled. Very hard formations will typically be drilled with hemispherical inserts; sandstone formations will typically use pointed inserts; and shaly formations will commonly use chisel-shaped inserts.
Drilling with Mixed Tooth Types
The present application discloses bits, rigs, and methods for rock penetration, using different types of teeth for a single bottomhole track.
For example, in one class of embodiments, a single row of one or more cones contains both pointed inserts and chisel-shaped inserts.
In another class of embodiments, the same bottomhole track is attacked by inserts of different diameters. (For example, a single non-gage row of a single cone can include inserts of different diameters.)
In another class of embodiments, the same bottomhole track is attacked by inserts of different heights. (For example; a single non-gage row of a single cone can include inserts which protrude upward to different heights.) This can advantageously be implemented, for example, using larger-diameter inserts for the ones which have greater protrusion from the cone.
In another class of embodiments, the same bottomhole track is attacked by inserts of different materials. (For example, a single row of a single cone can include inserts with different carbide compositions.) One particularly advantageous implementation of this is to combine different carbide compositions with different profiles, so that the inserts with the more “aggressive” profile have a more abrasion-resistant composition, and the inserts with a more “conservative” profile have a more fracture-resistant composition. (Another advantageous implementation is just the opposite, where the inserts with the more “aggressive” profile have a more fracture-resistant composition, and the inserts with a more “conservative” profile have a more abrasion-resistant composition.)
The disclosed innovations, in various embodiments, provide one or more of at least the following advantages, many related to efficiencies:    Physical efficiencies as related to failing multiple types of rock with one cutting structure containing multiple features/shapes/extensions/diameters;    Aggressive as related to addressing multiple types of rock (soft/hard/sandy/shaley/etc) with one cutting structure (containing multiple features/shapes/extensions/diameter);    Durability as related to addressing multiple types of rock (soft/hard/sandy/shaley/etc) with one cutting structure (containing multiple features/shapes/extensions/diameters);    Mechanical efficiencies (WOB/RPM) as related to failing multiple types of rock with one cutting structure (containing multiple features/shapes/extensions/diameters).
A further expected advantage, of some embodiments at least, is improved resistance to secondary tooth fractures induced by a first tooth fracture: when more durable teeth are mixed with less durable teeth, the more durable teeth are expected to be more resistant to secondary fracture.
It should also be noted that the advantages obtained by the disclosed innovations can be used in various ways: for example, increased durability can be traded off for higher ROP in a given formation, or vice versa.